Gasification is well known in the art and it is practiced worldwide with application to solid and heavy liquid fossil fuels, including refinery bottoms. The gasification process converts carbonaceous materials, such as coal, petroleum, biofuel, or biomass with oxygen at high temperature, i.e., greater than 800° C., into synthesis gas, or syngas, steam and electricity. The syngas can be burned directly in internal combustion engines, or it can be separated or used to produce methanol via synthesis, or converted into synthetic fuels via the Fischer-Tropsch process. There are two reactor types used in gasification: refractory and membrane wall reactors. The latter process requires solid particles in the feedstock and therefore is applied to solid fuels or liquid fuels containing solids.
Gasification uses partial oxidation to convert any carbon contained in a feedstock into synthesis gas consisting of carbon monoxide (CO) and hydrogen, which in turn can be used in the manufacture of various chemicals ranging from fertilizers to liquid fuels or petrochemicals. According to the desired end product, the gasification process unit or block incorporates several technologies.
For refining applications, the main process block is known as the Integrated Gasification Combined Cycle (IGCC), which converts the feedstock into hydrogen, power and steam. FIG. 1 shows the process flow diagram of a conventional IGCC of the prior art. The IGCC is a complex integrated process, consisting of sections, including feed line 101 and feed preparation 102, air separation unit 180 with oxygen feed 103, gasification reactor 104 producing syngas 106, syngas quench and cooling unit 110, with generated steam 112 and cooled syngas 114 passing to water-gas shift reactor 120, acid gas removal (AGR) and sulfur recovery unit (SRU) 130 for treatment of shift gas 122 and separation of carbon dioxide 136 and sulfur 138, high hydrogen syngas recovery 132 and/or gas (WGS) turbine feed 134, and a combined cycle package including gas turbine 140 with air feed 142 for producing electricity 144 and a high pressure discharge 146, a heat recovery steam generator (HRSG) 150 receiving steam 116 and boiler feed water 152 and producing steam 154 and boiler feed water 156 for delivery to cooling unit 110, and steam turbine 160 for producing electricity 162.
The air separation unit 180 and most of the downstream processes utilize mature technologies with high on-stream reliability factors. However, the gasifier 104 has a relatively limited lifetime that can be as short as from 3 to 18 months, depending upon the characteristics of the feed and the design of the unit.
Three principal types of gasifier technologies are moving bed, fluidized bed and entrained-flow systems. Each of the three types can be used with solid fuels, but only the entrained-flow reactor has been demonstrated to process liquid fuels. In an entrained flow reactor, the fuel and oxygen and steam are injected at the top of the gasifier through a co-annular burner. The gasification usually takes place in a refractory-lined vessel which operates at a pressure of about 40 to 60 bars and a temperature in the range of from 1300° C. to 1600° C.
For production of liquid fuels and petrochemicals, the key parameter is the H2/CO ratio of the dry syngas. This ratio in the syngas produced is usually between 0.85 and 1.2 depending upon the feedstock characteristics. Thus, additional treatment of the syngas is needed to increase this ratio up to 2 for Fischer-Tropsch applications or to convert CO to hydrogen through the water-gas shift reaction represented by CO+H2O═CO2+H2. In some cases, part of the syngas is burned together with some off gases in a combined cycle to produce power and steam. The overall efficiency of this process is between 44% and 48%.
The major benefits for a refinery using a heavy residue gasification process are that it provides a source of hydrogen for hydroprocessing to meet the demand for light products; it produces power and steam for refinery use or for export and sale; it can take advantage of efficient power generation technology as compared to conventional technologies that combust heavy residue; and it produces lower pollutant emissions as compared to conventional technologies that combust heavy residues for disposal. Furthermore, the process provides a local solution for heavy residue where produced, thus avoiding off-site transportation or storage; it also provides the potential for disposal of other refinery waste streams, including hazardous materials; and a potential carbon management tool, i.e., a CO2 capture option is provided if required by the local regulatory system.
Gasification technology has a long history of research and development, and many units are in operation worldwide. For refining applications, it is of potential utility where hydrogen is needed for hydroprocessing and natural gas is not available, and the prices of the feed used for gasification are very low. This is usually the case in refineries where full conversion is required to meet the demand of cleaner light products, such as gasoline, jet fuel and diesel transportation fuels.
The gasifier conventionally uses refractory liners to protect the reactor vessel from elevated temperatures that range from 1400° C. to 1700° C., corrosive slag and thermal cycling. The refractory is subjected to the penetration of corrosive components from the syngas and slag and thus subsequent reactions in which the reactants undergo significant volume changes that result in strength degradation of the refractory materials. The replacement of refractory linings can cost several millions of dollars a year and several weeks of downtime for a given reactor. Up until now, the solution has been the installation of a second or parallel gasifier to provide the necessary capacity, but the undesirable consequence of this duplication is a significant increase in the capital costs associated with the unit operation.
Research has been reported that is directed to means that will increase the useful life of the gasifier refractory material and thus increase the economic competitiveness of the gasification process. This includes new refractory materials and new technologies such as membrane reactors which are expected to have high reliability and high availability compared to that of conventional lined refractory reactors.
Membrane wall gasifier technology uses a cooling screen protected by a layer of refractory material to provide a surface on which the molten slag solidifies and flows downward to the quench zone at the bottom of the reactor. The advantages of the membrane wall reactor include reduced reactor dimensions as compared to other systems and elimination of the need to have a parallel reactor to maintain continuous operation as in the case of refractory wall reactors; the on-stream time for a typical refractory wall reactor is 50%, therefore a parallel unit is required; however, the on-stream time for membrane wall reactors is 90% and there is no need for a second, parallel reactor; and the build-up of a layer of solid and liquid slag provides self-protection to the water-cooled wall sections.
The build-up of a layer of solidified mineral ash slag on the wall acts as an additional protective surface and insulator to minimize or reduce refractory degradation and heat losses through the wall. Thus the water-cooled reactor design avoids what is termed “hot wall” gasifier operation, which requires the construction of thick multiple-layers of expensive refractories which will remain subject to degradation. In the membrane wall reactor, the slag layer is renewed continuously with the deposit of solids on the relatively cool surface. Further advantages include short start-up/shut down times; lower maintenance costs than for the refractory type reactor; and the capability of gasifying feedstocks with high ash content, thereby providing greater flexibility in treating a wider range of coals, petcoke, coal/petcoke blends, biomass co-feed, and liquid feedstocks.
There are two principal types of membrane reactor designs that are adopted for processing of solid feedstocks. One such reactor uses vertical tubes in an up-flow process equipped with several burners for solid fuels, e.g., petcoke. A second solid feedstock reactor uses spiral tubes and down-flow processing for all fuels. For solid fuels, a single burner having a thermal output of about 500 MWt has been developed for commercial use.
In both of these reactors, the flow of pressurized cooling water in the tubes is controlled to cool the refractory and ensure the downward flow of the molten slag. Both systems have demonstrated high utility with solid fuels, but not with liquid fuels.
Delayed coking is a thermal cracking process used in petroleum refineries to upgrade and convert petroleum residuum, which are typically the bottoms from the atmospheric and vacuum distillation of crude oil, into liquid and gas product streams leaving behind petroleum coke as a solid concentrated carbon material. A fired furnace or heater with horizontal tubes is used in the process to reach thermal cracking temperatures of 485° C. to 505° C./905° F. to 941° F. With a short residence time in the furnace tubes, coking of the feed material is thereby “delayed” until it is discharged into large coking drums downstream of the heater.
In the practice of the delayed coking process, a hydrocarbon oil is heated to a coking temperature in a furnace or other heating device and the preheated oil is introduced into a coking drum to produce a vapor phase product, which also forms liquid hydrocarbons, and coke. Coke can be removed from the drum by hydraulic means or by mechanical means.
In most configurations of the delayed coking process, the fresh hydrocarbonaceous feed to the coking unit is first introduced into a coking unit product fractionating column, or fractionator, usually for heat exchange purposes, where it combines with the heavy coking unit oil products that are recycled as bottoms to the coking unit heater. It is known that decreasing the recycle ratio of the fractionator bottoms that are recycled to the delayed coker furnace results in an increase in the hydrocarbon liquid yield and a decrease in the coke yield of the delayed coker. Thus, the effect of the recycle ratio to coke yield is such that as recycle decreases, the cut point of the recycle increases.
A delayed coking process is disclosed in U.S. Pat. No. 4,492,625 in which the hydrocarbon feedstock having a boiling point of 925° F./450° C. is split before the furnace heating step with one portion being sent to the delayed coking unit furnace and a second portion being introduced directly into the coking unit product fractionator. At least a portion of the bottom residue, or bottoms, from this fractionator is recycled to the furnace where it is combined with the fresh hydrocarbon feedstock, and the combined feedstock is heated to a predetermined coking temperature and passed to the delayed coking unit.
The boiling point of the feedstream employed in the process described in the '625 patent indicates that the hydrocarbon feedstream had been previously upgraded, e.g., by vacuum distillation before processing in the delayed coking unit and being introduced into the fractionator above the coking unit product feed to the fractionator. There is no significant effect on the capital or operating costs associated with the operation of the product fractionator in this mode. Rather, it is equivalent to the conventional steps of atmospheric distillation followed by vacuum distillation of whole crude oil, followed by coking of the residuum or bottoms.
A process is described in U.S. Pat. No. 4,066,532 for delayed coking in which the fresh feedstock is introduced to a preheating furnace as a mixture with the bottoms and a portion of the heavy gas oil side stream from the coking unit product fractionator, or fractionating column. It is stated that the recycling of the heavy gas oil will result in an increase in the aromaticity of this side stream, a portion of which can advantageously be used for carbon black production. The fresh feedstock is described as including coal tar and decanted cracking oil having prescribed sulfur, ash and asphaltene contents. The temperature of the mixed feedstock is raised to 450° C. to 510° C./842° F. to 950° F. in the preheating furnace.
A catalytically enhanced delayed coking process is described in U.S. Pat. No. 4,394,250 in which from about 0.1% to 3% of catalyst and hydrogen are added to the feedstock before it is introduced into the furnace with a portion of the fractionator bottoms. The feedstock is selected from heavy low-grade oil such as heavy virgin crude, reduced crude, topped crude, and residuums from refining processes.
It is an object of this invention to provide a process that is capable of producing syngas products that can be used as a feedstream for other processes in the same refinery by the gasification of heavy refinery residual oils in which a sufficient amount of solid ash-forming material is provided from a source in the same refinery that is reliable, energy-efficient and environmentally acceptable.